Core Laboratories N.V. (CLB) Q1 2015 Earnings Report, Transcript and Summary

Hello. And welcome to the Core Laboratories LP First Quarter 2015 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to David Demshur, Chairman, President and [CFO] [ph]. Mr. Demshur, please go ahead.

Well, thanks, Keith. I’d like to say good morning in North America, good afternoon in Europe and good evening in Asia Pacific. We’d like to welcome all of our shareholders, analysts and most importantly, our employees to Core Laboratories’ first quarter 2015 earnings conference call. This morning, I am joined by Dick Bergmark, Core’s Executive Vice President and CFO; Core’s COO, Monty Davis, who will present the detailed operational review; and Chris Hill, who will become the Core’s Chief Accounting Officer as Brig Miller is retiring at the end of April. Brig has served the company and its shareholders well with 18 years of dedicated work. Brig made Core a better company and a more profitable institution, while building true shareholder value. He is a great friend to all and will be miss by all. The call will be divided into five segments. Chris will start by making remarks regarding forward-looking statements. Then we will come back and give a review of current market conditions and give an analysis of Core Lab actions into 2008-2009 market downturn compared to Core Lab actions taken during the first quarter 2015. Then we will some comments on three technological targets and technologies to be introduced and applied in 2015 as directed by our clients. Dick will then follow with a detailed financial overview and additional comments regarding building shareholder value, Core’s second quarter 2015 outlook and a general industry outlook as it pertains to Core’s continued growth prospects. Then Monty will go over Core’s three operating segments, detailing our progress and discussing the continued successful introduction of new Core Lab technologies that relate to completing, stimulating and producing horizontal wells and then highlight some of Core’s operations and major projects worldwide. Then we’ll open the phones for a Q&A session. I’ll turn it over to Chris for remarks regarding forward-looking statements. Chris?

Thanks, Dave. Before we start the conference this morning, I’ll mention that some our statements that we make during the call may include projections, estimates and other forward-looking information. This would include any discussion of the company’s business outlook. The types of forward-looking statements are subject to a number of risks and uncertainties relating to the oil and gas industry, business conditions, international markets, international political climate and other factors, including those discussed in our 34 Act filings that may affect our outcome. Should one or more these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, forward events or otherwise. For more a detailed discussion of some of our foregoing risks and uncertainties, see item 1A, Risk Factors, in our annual report on Form 10-K for the fiscal year December 31, 2014, as well as other reports and registration statements filed by us with the SEC and the AFN. Our comments include non-GAAP financial measures. Reconciliation to the most directly comparable GAAP financial measures is included in the press release announcing our first quarter results. Those non-GAAP measures can also be found on our website. With that said, I’ll pass the discussion back to Dave.

Okay. Thanks Chris. Core believes that the worldwide crude oil supply and demand markets are well underway for year end 2015 balance. On the crude oil supply side, U.S. production is beginning to rollover as we speak. No one needs to look at Bakken production for January and February of this year. It has already fallen by 50,000 barrels a day year-over-year or about 4%. With respective decline curve rates of 70%, 40% and 20% for the first three years of production in the Bakken, significant year-over-year declines will manifest themselves as 2015 progresses and into a sharp decline in 2016. Ditto this for the Eagle Ford, Permian, Niobrara and other liquids rich unconventional plays. There is a possibility of year-over-year U.S. production declining at the end of 2015. What we need to do is compare the production totals in December of ‘15 with the production totals of December of ’14 and we would not be surprised if December ‘15 numbers were down from there. This is a far cry from past year-over-year gains of 1 million barrels plus for U.S. operations. Internationally, Core does not believe that recent increases in production from the Middle East and Russia are sustainable over the long run. Decline curves in Russia will be greater than the 2.5% net used by Core on a worldwide basis. This is on a production base of about 10.2 million barrels per day. Additional gains from deepwater fields on both South Atlantic margins in 2015 will be muted compare to those gains in 2013 and 2014. Therefore by year end, Core sees crude oil markets in balance owing to these production stagnations internationally and declines possibly in the U.S., while demand increases due to these lower commodity prices and a recovering worldwide economy. Worldwide year-over-year demand increased by 1.3 million barrels in Q1, while the IEA projects year-over-year worldwide demand to be up 1.1 million barrels for all of 2015, balancing supply and demand by year end of 2015. Therefore, Core sees a V shaped recovery led by higher commodity prices and then shortly there followed by increased worldwide drilling activities in the start in early 2016. With that being said, let’s look at Core’s actions in the first quarter of 2015, compared to those taken in the early downturn stages of 2008 and 2009. Basically we see the 2008/2009 downturn playing out very similar to this downturn. In 2008/2009 we had a reduction in force of approximately 300 employees, most of these from North America, most concentrated in the U.S. In Q1 2015, we have had a reduction in force of approximately 600 employees. We will use great automation and streamlining of work efficiencies for recovery in early 2016 as we see activities rebounding. This reasons with the increased efficiency has led to the increase number of employees that we reduced this time around. This positions Core to react to increasing activity levels in 2016 that will lead to continued revenue growth at 200 to 400 basis points above worldwide activity levels, while seeing incremental margins on the high-end of our historical range of 35% to 45%. Now looking at the three technological targets for 2015 as per our client input, as we highlighted in the release and will have in the discussions, Core has three technological targets for 2015. Number one is the continued evolution of the company's industry-leading reservoir fluids phase-behavior PVT business, number two, refrac of existing horizontal wells in unconventional reservoirs, and the third being, we are seeing greater interest in EOR projects in unconventional reservoirs, the number of which will be discussed by Monty Davis during the operational review. Core’s -- clients worldwide are realizing the value of PVT data in maintaining base production as demonstrated by Core’s fluids business in our Aberdeen advanced technology center. North Sea activity levels continued to decline, while Core's Reservoir Fluid business in the North Sea continues decline and has never been in higher levels. On refracs, we are in the early learning stages for almost all operators. The Core has recently introduced tracer technology coupled with the company’s HTD-Blast perforating technology that will enable successful refracs into the second half of 2015 continuing into the year 2016. For EOR projects, a year ago we had one of these in unconventional reservoirs from one of our most technologically sophisticated clients. In the first quarter, we’ve done five and are working on a number of other projects. We are trying to get the average unconventional recovery factor from the upper-single digits into the lower-double digits, maybe from 9% to 12%, which has a significant impact on return on invested capital of our clients. I will now turn it over to Dick for a detailed financial overview.

Thank you, David. Just a couple of points on our financial results before we go through the statements. We commented on our earlier call that we felt our Reservoir Description segment’s revenues and margins would hold up very well in this first quarter of the down cycle, and they did. In fact, they exceeded our expectation. We also commented that our Production Enhancement segment may not do as well given the sharp reduction in industry activity in North America. We also emphasized that because the segment is a larger part of our business today with higher margins that it was back in the 2008-2009 cycle, that it probably would not fair as well as it did in the last cycle. You can see that in these results. Importantly, though, the margins in our Production Enhancement segment this quarter are the highest reported to-date by any company’s North American activity. Also, as a result of our strong working capital management, our free cash flow of nearly $73 million in the first quarter exceeded our earlier projections. Now looking at the income statement. Revenues were $213.6 million in the first quarter versus $262.9 million in the first quarter of last year, which is a 19% reduction year-over-year, which in fact is a very nice outcome considering worldwide rig count was down 29% over that same time period. And in fact, on a constant currency basis, our revenues were down only 15%. Of these revenues services for the quarter $163 million, down 14% compared to the last year’s quarter. Product sales, which are more tied to North American activity, are lower for the quarter at $50.7 million compared to $74.2 million in last year’s first quarter. We look at cost of services for the quarter they are 63.1%, up when compared to 58.6% in last year’s first quarter. Although this was up slightly, our service operating margins continue to be strong, which confirms that pricing do not play a big part in our lower margins, rather it was the absorption of our fixed cost structure on lower revenue. Our cost of product sales is 81.9% of revenues, which are up from 68.9% in last year’s first quarter. G&A for the quarter is $12.7 million, which is up from last year, primarily due to compensation expense. Depreciation and amortization for the quarter is $6.6 million, which is unchanged from last year. Severance and other charges, a line item specific to this quarter, as mentioned in our earnings release we’ve taken actions to appropriately align our cost structure, and as a result have recorded a charge of $7.1 million in the first quarter, which is primarily related to employee severance expense. Other expense this quarter primarily includes foreign exchange losses of $800,000. The guidance we gave on our call for this quarter specifically excluded the impact of any FX gains or losses. So accordingly our discussion today and pro forma EBIT and EPS excludes this foreign exchange loss. Excluding those FX losses, severance expense and other charges to conform to our guidance pro forma EBIT in the quarter was $50.7 million compared to $84.4 million pro forma EBIT in last year’s first quarter. Ex-items EBIT margins were 23.7% for the quarter, GAAP EBIT $42.7 million. Income tax expense in the quarter is $11.1 million based on an effective tax rate of 23%. Net income for the quarter ex-items is $37.5 million compared to $62.3 million ex-items last year, while GAAP net income is $31.4 million. Earnings per share for the quarter is $0.86 on a same basis that our guidance was given and is above the average street guidance of $0.85. Our GAAP EPS, which includes the additional charges this quarter, is listed on the reconciliation table to our earnings release was $0.72 per share. We look at the balance sheet. Cash is $19.1 million, down slightly from year end. Receivables stand at a $159 million, down from $197.2 million at prior year end. Our DSOs in the quarter though are 64 days, which is unchanged from that experience for all of 2014. Inventory was at 4$9.2 million, is up from the year end balance and the increase is due to pre-year end commitments based on expected activity levels existing before November 27. You should expect inventory to trim down as the year progresses. And there are no material changes from year end in other current asset PP&E, intangibles and goodwill and other long-term assets. We look at the liability of the balance sheet. Accounts payable up slightly from year end, other current liabilities are slightly down at $80.5 million from year end, $84.8 million primarily due to the timing of accruals and payments for various liabilities. Long-term debt stands at $373 million compared to $356 million last quarter and is comprised of a $150 million in senior unsecured notes and $223 million drawn on our bank revolving credit facility at quarter end. The increase in borrowings came as a result of our increased share buyback program. As of today, drawings under our credit facilities are $244 million. During the quarter we did exercise a $50 million accordion feature on our revolving credit facility, which increased our availability to $400 million. This new expansion of the facility also included a further $50 million accordion, which if exercised would raise the availability to $450 million, shareholders' equity into the quarter at $32.5 million primarily due to share repurchases and dividends in excess of net income since the end of last year. And depending on this size of our share buyback activity this coming quarter, we may actually see book equity bill below zero. Clearly, historical book equity does not represent the solvency of a company. We also note that several S&P 500 companies to generate significant levels of free cash flow also have negative book equity because they return their free cash to their owners just as we have done. We have not debtor contract compliance requirements to report positive net worth. Capital expenditures for the quarter are $6.9 million, down from $7.7 million in the first quarter of last year. These expenditures for the most part were result of pre-year end commitments based on expected activity levels existing before November 27. Given the current downward trend of the industry activity levels, we expected our CapEx will also begin trending down. We expect our CapEx program in 2015 to track client demand for services and products, so consequently we expect CapEx in 2015 to be lower than 2014. Look at cash flow, cash from operating activities in the quarter were $79.6 million and after paying for $6.9 million in CapEx, our free cash flow is $72.7 million. This is our largest free cash flow first quarter ever. In fact, in the quarter we turned over 34% of our revenues in the free cash flow and that’s one of the highest cash conversion rates in our industry. Our focusing on managing the business during this challenging environment continues to be focused on maximizing free cash flow and return on invested capital. During the quarter, we used our free cash flow, cash balances and borrowings to pay $23.9 million in quarterly dividend and repurchased 683,290 shares for $72.9 million. To the close of business yesterday in the second quarter, we have repurchased a further 153,129 shares at an average price $116.56 and an aggregate cost of $17.8 million. The outstanding indebtedness under our revolver now stands at $244 million, compared to $206 million at the end of 2014. Our diluted share count today stands at 43 million shares. Now for our Q2 guidance and outlook for the remainder of the year. David said the balancing of worldwide crude oil markets is well underway. U.S. production is starting to decline in the second quarter of 2015 and the most recent international energy agency estimates project worldwide demand to increase in 2015 by 1.1 million barrels of oil per day in a respond to seasonally low commodity prices. We now believe the U.S. supply growth will roll over in May or June of 2015 and that year-over-year crude oil production will be flat to down. Therefore, the current activity levels in the field, U.S. production could fall significantly in 2016. While worldwide oil production continues to stagnate or decrease slightly because recent international production gains may not be sustainable over the long-term. We continue to project North American and international activity levels to decline in the second quarter. Therefore, we project that second quarter revenue will range between $192 million and $202 million, with EPS ranging between $0.76 and $0.81. Free cash flow for the second quarter is expected to exceed $60 million, significantly greater than projected net income. And all operational guidance excludes any foreign currency translation and any shares that maybe repurchased other than those already disclosed and it assumes an effective tax rate in the quarter of 22.5%. Our view for the remainder of the year continues to be constructive yet uncertain, while our customers are prioritizing operating plans for conducting their activities in this environment. Consequently, we may not be able to provide quantitative guidance for the remainder of the year at this time. Although from a qualitative perspective, our sense is that industry activity levels will flatten in the third and fourth quarters of 2015, with a V-shaped recovery as David discussed starting in the first quarter of 2016. So next, Monty will provide a detailed operational review.

Thanks, Dick. Q1 revenue was $213.6 million, yielding operating earnings of $50.7 million at a 23.7% margin, excluding of course FX loss, workforce reduction and certain exit costs, all that in a market where the worldwide rig count was down 29% year-over-year. I want to thank our employees for working to deliver value to our clients to reservoir optimization technologies offered around the globe. Reservoir Description revenues for Q1 were $121.8 million. At a constant exchange rate, revenues would've actually grown 3% over Q1 2014, despite the 29% drop in worldwide rig count. Margins of 27% yielded $32.4 million in operating earnings-ex that I just mentioned before. Core’s reservoir fluid analysis services led the way in Q1 with continued strong performance, providing operators with critical studies of our existing production and development of new oil fields around the globe. In Q1 2015, Core provided fluid analysis services to over 55 clients in the following U.S. shale plays -- Tuscaloosa, Eagle Ford, Marcellus, Utica, Powder River Basin, Anadarko Basin, Niobrara, Bakken, Permian Basin and Avalon. On the EOR front, Core performed five studies in Q1, where several clients holding property in the Tuscaloosa and Eagle Ford shales. And this service line could grow rapidly in the years to come, since it is the most effective way for companies to extract the incremental oil left behind due to pressured depletion. Core’s experience, capability and capacity have made it a dominant reservoir fluid analysis provider in the U.S. land market. In the deepwater Gulf of Mexico market, Core’s primary fluid activity consists of handling high pressure fluid samples either on-site with our mobile laboratories or in our laboratory facilities in Houston and Lafayette, Louisiana. During logging runs, sampling tools collect pressurized reservoir fluid that we transfer into ultrahigh pressured sample cylinders for initial contamination evaluations and long-term storage. Core performs various studies, including PVT up to 30,000 psi, flow assurance and EOR. The reservoir fluid collected is key to critical economic decisions, which requires knowledge of the expected life of the reservoir on primary production determined by PVT and the overall quality of the oil determined by compositional and other chemical analysis. Information provided by Core Lab is used by clients to decide whether or not to return to a particular discovery in the future and what type of surface facilities would be required to optimize recovery of this unique oil from this particular reservoir. As with the land shales, deepwater Gulf of Mexico clients are starting to explore the feasibility of EOR to get incremental oil out of their prospects. Along with fluid, assurance studies performed in Core’s unique pressurized fluid imaging system to determine what may plug client production lines, asphaltenes, waxes and hydrates and how they can be remediated. Deepwater Gulf of Mexico clients are requesting ultrahigh pressure, 20,000 psi and above EOR studies. Core’s performed a number of flow assurance and EOR studies for clients and expect the demand for these tests to increase as Core’s the only provider of these services at the pressures experienced in the deepwater environment. Production enhancement is heavily weighted in the North America market where the rig count fell by 32% in the first quarter. Production enhancement revenues of $75 million are down 32% from Q1 2014 and margins of 18% are the highest reported for any North American-based operation this quarter. This segment was affected not only by declining rig count but additionally by wells being drilled but not completed in North America. On one of our recent projects, we utilized our SpectraScan and SpectraChem diagnostic services to evaluate sliding sleeve technologies for one of our clients. Our diagnostics determined that frac sleeves were repeatedly not performing as intended, resulting in large sections of misplay across the lateral. This led to a change in their field-wide horizontal completion designs to plug-and-perf. The plug-and-perf completion designs yielded significantly improved hydrocarbon production. Our diagnostic results also proved that affective frac coverage across the targeted pay intervals was achieved when utilizing the plug-and-perf design. We are currently in the process of using our diagnostic services to further optimize the various completion design parameters in this field. In Core Labs, ballistic engineers have been working on a number of plug and abandonment project for customers in the U.K., Gulf of Mexico, Thailand and Australia. These projects are focused on well abandonments for offshore market where customers are required to establish isolation of producing zones from exposure to the surface. Prior to the introduction of Core’s proprietary plug and abandonment circulation operating systems, operators utilized a time-consuming section mailing technique. Our operating systems can efficiently facilitate the cement plugging operation by providing larger entry holes in area opened to flow for their required hydraulic isolation. Recently a plug and abandonment circulation perforating system was utilized in Norway to facilitate a cement plugging operation between 9.625 and 13.375 well casings by controlling the penetration in the interfacing with a 0.75-inch hole and zero penetration of the outer casing. A successful cement plug was squeezed through the perforations to fully comply with the abandonment regulations. The operation saved 13 days of on-site work compared with section milling saving our client over $7 million. We continue to be active offshore with the suite of completion diagnostic services used to evaluate the success of gravel pack completions. We performed the services on four of the six major Walker Ridge ultra-deepwater fields, namely, Jack, St. Malo, Cascade and Chinook and are scheduled to perform diagnostics on the other two fields, Stones and Julia. Our patented wash pipe conveyed diagnostics have helped to ensure successful completions in ultra-deep offshore zones either by identifying successful operations, identifying failures that can then be remediated. Reservoir management revenues of $16.7 million generated 25.4% operating margins. A significant factor in our year-over-year revenue and margin declined for reservoir management was an $8 million reduction in revenue from the Canadian oil sands. In North America, reservoir management added new members to our highly successful joint industry project focused on the reservoir characterization, fracture stimulation and production performance of the East Texas Eaglebine play. Over 125 representatives from the 13 member companies attended the workshop and seminar held in the first quarter. Interest has also remained high for our Utica-Point Pleasant project in the Appalachian basin which now has 21 members. This play has taken on a new life with monster gas wells with initial production in the 20 million to 60 million cubic feet per day being reported in Pennsylvania and West Virginia. Projections from our regional mapping into Pennsylvania led several companies to test these areas underlying the Marcellus. Several new cores have been contributed to our Permian basin project and are being analyzed. This brings the total number of cored wells in the Permian projects to over 140. Reservoir Management also continued work on the unconventional Duvernay, Montney, and Wilrich projects in Canada. Internationally, Reservoir Management also completed the first phase of its Central Atlantic Margin Regional Geological and Petrophysical Joint-Industry Study. The study encompasses Senegal, Gambia, and the AGC. Industry interest in the area is growing following discoveries drilled in 2014. Several new participants were added in the quarter. We further extended our portfolio in the Central Atlantic with the launch of a new joint-industry project in Suriname. It is anticipated that this will extend into Guyana during the second quarter. The Central Atlantic remains a focus area with projects from Senegal to the Ivory Coast. Keith, we’ll now open the call for questions.

Yes.Thank you. [Operator Instructions] And the first question comes from Rob MacKenzie with Iberia Capital.

Good morning guys.

Good morning Rob.

I guess, question for you on your comments regarding shareholders equity. In the past, I know you guys have the view point that you were not going to take shareholder’s equity negative in part. If I recall correctly because you have some customer, customers reviewed that as the sign of insolvency. What has changed there to give you comfort in doing so? And second what are your thoughts about potentially doing a leverage to buyback?

Rob, we have -- had discussions and review and we’re comfortable that negative network does not impact any of our contracts or any of our debt covenants. So that's really no longer an issue for us. We're doing a recap as we speak every quarter. We continue to buyback using our free cash and we’ve augmented that since say the middle of last year with additional borrowings under our facility and you’ve seen us increase the size of the facility starting back in Q3 last year and again in Q1 this year.

I guess, -- let me rephrase the question, what’s your view about potentially doing something a lot more incremental than what you’ve been doing each quarter perhaps a Dutch auction or some other process taking down a lot of shares if that’s a cyclical trough here?

Our bank facility has in a debt-to-EBITDA limit of 2.5 to 1 and we’re comfortable in that 2 to 1. And we have a philosophy of averaging in. And I think you'll continue to see us do it that way.

Great. Thank you. I’ll turn it back for now. Thanks guys.

Okay. Thanks Rob.

Thank you. And the next question comes from Chase Mulvehill with SunTrust.

Hey good morning fellows.

Good morning Chase.

Yes. So I guess, a quick -- I guess comments or questions on the refrac market. How big do you see the refrac market this year and then kind of where could it go next year?

Yeah. If we look at refracs, this is not the easiest technological -- it's not the easiest thing to do. First of all, you’ve got sliding sleeves in wellbore. Refracs are kind of out of balance. Moreover, if you look at just horizontal wells that have been perforated and stimulated using plug-and-perf, those are no longer candidates for additional plug-and-perf. And we have to go in with specialized technologies. It just so happens that Core Lab's HTD-Blast perforating system delivery system is especially made exactly for that. Also if you look at trying to stimulate new reservoir rock because I think that’s the key here as opposed, we’re just going and refracing the existing perforations which I think you'll get some benefit out of, but I think we want to stimulate new reservoir rock. So we’re going to need additional perforation clusters along the wellbore. Then comes the problem of trying to get the proppants and the hydraulic fracing fluid in those. Those can be isolated using a high viscosity slug to isolate those zones and thus slug later breaks down with some gel breakers to deliver that with production to the surface. So right now we are intensely studying different methods because so many completion and stimulation methods have been used. So to answer your question probably not a needle mover until somewhere in the fourth quarter going into the first quarter of next year, the number of wells that are candidates for that, number in the tens of thousands. So depending on where commodity prices are at, I think that's going to be really the governing factor in how large that market becomes. Obviously the lower -- the longer that we have lower commodity prices that becomes a bigger market. If we get a rebound in commodity prices as per our theory, the refrac market will be there but it will never realize the size it would, with let's say, $50 WTI and $60 Brent.

Absolutely. Okay. And if we look at Core Lab, so what's your revenue opportunity per refrac?

Well, if you think of looking at our production enhancement segment because that would be the guys that are involved.

Yeah.

If you look at the number of stages that are completed or in this case, recompleted or new stages, that becomes a revenue opportunity for us in each one of those refrac wells because we would have perforating clusters involved. And then a real key would be the use of a tracer technology that Monty talked about to ensure that new perforating clusters were being stimulated alongside if you wish to restimulate the old perforating clusters. So this number of stages will be the controlling factor. I will say that our new technology introduction, all in all you can see production enhancement revenue is down but it’s interesting in analyzing per stage, actually revenue is up. So the ones that are using these innovative technologies are using more of it, trying to capture greater initial production and production over the life of the wellbore. So it all depends on the number of stages. If commodity prices stay lower for a longer period of time but greater revenue opportunity for us, if the rebound happens like we think it will, a revenue opportunity but never as great as it would be with low commodity prices. We’ll take the higher commodity prices if we had to choose.

Got it. Okay. And then real quick on production enhancement in margins and thinking about the recovery in margins, how should we think about that as we move forward? Because you’ve taken a lot of cost out of the system rightsizing that business. I imagine it’s pretty scalable. So if margins probably going to be down in the second quarter, how should we think about the progress -- sorry --, revenues down the second quarter, how should we be thinking about the margin profile over the next few quarters?

Yeah. For the entire company, we might be seeing margins, trough margins in Q1. For production enhancement, a little tougher to say but probably we would see some -- we might see some additional deterioration but with the cost out, not as much as certainly we saw in quarter-over-quarter. So if we look at it from just a margin standpoint on the cost basis, we probably -- in production enhancement as well probably have seen tough margins in Q1 with all the cost coming out.

Okay. Awesome. I’ll re-queue. Thank you.

Okay. Thanks.

Thank you. And the next question comes from Blake Hutchinson with Howard Weil.

Good morning, guys.

Hello, Blake.

Dave, just wanted to expand upon a lot of the commentary in the release around the structural growth of the fully phase behavior PVT business. I guess, is the commentary more to point out that this is a continuum of the resilient in the business that’s kind of been a decade-long trend? Or have you spotted definitive acceleration really over just in a short period of time here from the down -- from that in the downturn? And how do you note that in your data, are people going deeper into their datasets or is the desire to retrieve data coming at shorter interval. How do you view that and call that kind of an acceleration trend?

Yeah. We actually did see the manifestation of this start in the last downturn where people realize they had to protect their base production. So when we think about the structural enlargement of this factor, think about not just new projects coming on but you’ve got a base production of 89 million-90 million barrels a day that is now a marketplace for this PVT data and phase-behavior data. Monty talked a little about on the exotic side some of the high-pressure ultrahigh temperature fluids but the market is building from that base production. So we saw that starting to grow in 2009 and it’s continued to incrementally grow through this downturn as well. So we’re very encouraged by that.

And Blake, there was this notion that reservoir description is reliant upon the initiation of new projects, primarily deepwater project. So goes those projects, so goes reservoir description with the thought. Clearly what we’re trying to show you is it's really that production, base production, base, day stocking about of 90 million barrels a day. They need PVT analysis done on it very frequently -- frequent basis and what's driving these great results out of their reservoir description.

Interesting to note, the place that we saw the most use of these data sets on base production was in the North Sea. And as you remember, Blake, a couple of years ago, we constructed some new roofline there for the expansion of that business. What is unique about the North Sea, high decline curve rates, well above our 2.5% net that we use on a worldwide basis. So technologically sophisticated clients are knowing these data sets can be used to not stop the decline curve, because we can’t open the laws of physics and thermodynamics, but they can somewhat abate what that decline curve would be.

And I guess, as it applies to the reservoir description revenue stream? I guess, I think about this business is maybe comprising, somewhere approaching two-thirds of the business that has a definitive year-over-year growth rate still where it’s the remaining portion of the business that will be more subject to the kind of 10% to 15% spending decline that you outlined in your release?

Yeah. I would say right now ...

Appropriate way to think about it?

Yeah. I wouldn’t say that would be that high as of yet. We’re probably approaching 60% on the fluids side, somewhere around 40% on the rock side. So you have that base fluids that certainly, if we use the constant currency view on year-over-year, you would see that reservoir description revenues would be up. There are some thoughts out there that reservoir description for whatever reason is in a structural decline, nothing could be further from the truth. If we look at the importance of reservoir fluids, that is a driving factor, of course, the rocks are important too. Any company that tries to do core analysis, meaningful important for reservoir development and sustainability of base production without a hearty reservoir fluid business is pulling themselves.

Great. That’s it for me. I’ll turn it back. Thanks, guys.

Okay, Blake.

Thank you. And the next question comes from Phillip Lindsay with HSBC.

Yeah. Good morning, gentlemen. Thanks for taking the question. Two questions …

Good morning, Phil.

Good morning. The first one, are you managing your cost base for of a V-shape recovery i.e. to try and protect the key infrastructure and the key assets of the business. Are you actually sort of managing your cost with an assumption behind it for a more conservative market outlook? That’s the first and I will come back to the second if you don’t mind.

Yeah. The way we've approached it is we listen to the clients, talk about where their activity levels are going to change, whether they are going to go down. But we try to take a view on where they going to go down, say permanently, but where in other areas, where they could go down, but maybe rebound. And the areas where we think they will rebound, we've used foremost more predominantly as it way to reduce our cost structure. So what’s a furlough, it’s a 20-day work month, we would tell depending on the level of activity, give them a 17-day work month or a 16-day work month and the employees happy they have a job, they have benefits, they are still employed and when you get recovery, they are immediately available to help you. In the areas where we think the activity levels will probably not come back anytime soon, that's where we’ve had reductions in force. So we try to be smart about it rather than using a brute force 10% reduction across the Board.

Okay. That makes sense. It’s good. And then second one, just a sort of broader question on pricing pressures and perhaps, if you could just talk about various business lines and a more -- what you are actually experiencing, presumably there is a little bit more pressure on production enhancement, just given that the North American buy for that business? But perhaps, you can just elaborate on that point? And also how you’re seeing the competition behavior thus far in the downturn?

We -- so this is Monty Davis.

Okay.

We do get request for reductions. We’ve worked with our clients on structuring, what we are doing for them. As always we are concentrating on the value we are delivering. In this market we are delivering the value to our clients. We’ve had some adjustment in some areas of pricing, but we haven't done anything huge, we don’t expect to, our prices don’t zoom up as things get tight, because we are not a commodity and so we didn't have that huge increase, we don't have the huge decrease either. I know you see that from some other companies that I won’t go through them, but you know the ones, where they had a big increase as the marketing got tight and then they come off just as heavily. We are not in that market. We value selling all the time. So certainly we’ve continued to do that. Although, I won’t say we have reduced prices in some areas, we work with our clients on a continuing basis. So it’s not a significant factor.

Can you say what areas that you are making the adjustments, can you say what they are?

Generally in more low end technologies.

Okay. All right. That's great. Thank you.

Bye, Phil.

Thank you. And your next question comes from Brandon Dobell with William Blair.

Thanks. Good morning, guys.

Good morning, Brandon.

Could you just focus on the EOR projects for a second, maybe some more color there, I guess kind of duration of these projects, magnitude? But most importantly, are these projects being sourced, I guess how they are being sourced between your bad debt guys in the company’s?

Yeah. Project, the length because these are rather tight rocks, can be multi-months and length could be multi hundreds of thousands of dollars in revenue for Core. We kind of like that revenue. Remember, a year ago we talked about the lack of Core’s for static reservoir characterization where we talked about EOR projects being a more dynamic testing with higher margins and we knew that the replacement of the static revenue with a dynamic revenue would lead to a margin support. So we had these projects that Monty spoke about in the first quarter, source directly from what we refer to as our most technologically sophisticated clients. And these can range from anywhere -- looking at for instance, the Bakken, a lot of the natural gas is being flared there even today, making use of those gases as opposed to flaring and maybe mixing in some heavier hydrocarbons, so light and heavier hydrocarbon floods. It can range from alternating water and natural gas floods. So right now early days for that. But we are looking at a combination of different flooding cocktails that can be used. And in one case there is an ongoing pilot project where a combination of heavy and light hydrocarbon gases, plus CO2, which is actually being trucked to the site. We are hoping to see results from that soon. In the laboratory, the results were very encouraging. So we will see more of these projects as we go through 2015 and will become critical for increasing the return on investment capital for our clients that are not only in the sweet spot of these plays, but some on more of the fringe areas of the plays.

Got it. Okay. And then David, within your comments around the V-shaped recovery starting in early ’16, maybe you could separate out or parse out how you think deepwater acts maybe between now and then or potentially as that recovery starts? What’s your perspective on deepwater activity?

Yeah. A kind of a -- Brandon, if we look at a kind of a tail of two cities here, when you look at the deepwater Gulf of Mexico. For us, this is going to be our most active year there and you’ve seen some support to the revenues and margins already manifest themselves in Q1. There have been a number of disappointments coming out of West Africa. Just yesterday, Conoco announced another deepwater well, was going to be classified as being non-commercial. So, I think outside of the deepwater Gulf of Mexico, deepwater at these commodity prices continues on with existing projects. But the initiation of new projects probably drags into the years 2016 and 2017. Now again, looking at reservoir fluids for those ongoing projects that base production continues to utilize those services. We are not seeing as much core or rock, but certainly we are saying similar or additional fluids coming from those established deepwater plays whether they be offshore Brazil, West Africa, Eastern Mediterranean, East Africa.

Okay. Great. Thanks a lot. I’ll turn it over.

Thank you. And the next question is from John Daniel with Simmons & Co.

Hey guys. Dave, do you think --

Good morning, John.

Good morning. Do you think that the refrac economics are more attractive than those generated on the new well drilling in completion?

It’s too early to tell. But one of the things that I think we are going to ascribe to as early indicated, we would point to let’s not only frac or pour wells, let’s go back and concentrate on your good wells, because your poor wells are probably related to poor reservoir rock which, okay, you can enhance the amount of production of recovery from those. We think the economics are going to, appoint to, go into your better wells and refrac. So we are going to need several more quarters and maybe over several more quarters to be able to determine that. And again, it’s going to all be related to the reservoir rock quality, technique used to originally perforate and stimulate and what kind of proppants we used. So, John, this is an incredibly multi-variant equation, that we’re just now starting to look into. But we must say that our clients now do realize that this is a very difficult and complex multi-variant equation to solve that. We kind of like that here at Core Lab because that brings a lot more of our data sets in the play.

Fair enough. But I’m not that smart and I’m going to keep this simplistic. But do you need -- it would seem that you need a lower threshold price to justify refracing versus drilling and completing the new well. And because the working theory out there from some folks, and I’d just like you to comment on is that the refrac opportunity creates a headwind in the recovery and drilling activity. Do you think that's a stretch?

I think it all depends on where you’re at reservoir rock. I can't answer that question for you, John.

Fair enough. But then at least, as you contemplate the V-shape recovery in early '16, that’s based off of a rig count driven recovery as to well completion recovery, is that fair?

Yes. I think one of our comments were if we had a decision between low commodity prices and refracs and high commodity prices, we’ll take the high commodity prices.

Sure. Fair enough. Okay. Thanks, guys.

Okay, John.

Thank you. [Operator Instructions]

Keith, we’ll take one more question.

Okay. Very good. And that question actually is a follow-up from Chase Mulvehill with SunTrust.

Yes. Thanks. Let me get back in. So, I guess, I wanted to ask a question. As you guys kind of know -- it seems like you guys know the U.S production lot better than a lot of the other guys. So if we think about what the year end '14 U.S. unconventional liquids production number, think about what that was, what do you think that declines this year, so what's your base decline rate?

Okay. If you look at year-end shale production U.S., we’re using about 5.4 million barrels. We are using 5.6 at the end of April. We've already seen that actually if we use a projection, let’s say a 55, 150 for May, we already see that going into decline. So if you look at and say that production came essentially from the last four years, so trying to boil this down a little bit. And you use decline curves of 70, 40, 20, and 10 for those four years. Chase, you could do the math as well as I can without adding any additional production on that. You can be down a million barrels next year. So in using Bakken data, because -- and the reason we like to talk about the Bakken is because everybody can use that data available from northdakota.gov just hit Bakken production. We might not agree with all that data but we use it, because you guys have access to that. It would suggest that, if you look at the Bakken which has lost 4% of his productive capacity just in the two months of January and February of this year, a total of 42 completions took place in February. You need 115 Bakken completions a month to maintain production. Last year the average Bakken completions per month were 162. You can see you’re going to have a dramatic tail off in the amount of shale production, if we remain at the levels that we are now. So as we talked about, we could exit 2015 year-over-year with total U.S. production being down. And most of that significantly related to the unconventional production. We could be down as much as a million barrels a day in 2016. So depending on activity levels, that’s kind of what we are thinking right now.

Awesome. Thanks. That’s very helpful. And then last one, do you have internal targeted net debt to EBITDA, or one that you would like to share?

Yes. We talked about a comfort level in the two times EBITDA on our debt.

Okay. Awesome. That’s all I have. Thanks, Dick. Thanks, Dave.

Okay, Chase. Keith, we’re going to wrap. So in summary, Core’s operations have positioned the company for increased activity levels in early 2016, but we know significant challenges stills await in 2015. However, we have never been better operationally or technologically positioned to help our clients maintain and expand their production base. We remain uniquely focused in on the most technologically advanced reservoir optimization company in all oilfield services. This positions Core well for the challenges ahead. The company remains committed to industry-leading levels of free cash generation, returns on invested capital with the free cash and the additional borrowings being sent back to our shareholders, the share repurchases and dividends. So in closing, we would like to thank all of our shareholders and the analysts who follow Core and as already noted by Monty Davis, the executive management and Board of Core Laboratories gives a special thanks to our 4,400 worldwide employees that have made these results possible. We are proud to be associated with their continuing achievement. So thanks for spending your morning with us. And we look forward to our next update. Good bye for now.

Thank you. The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.